While rich in natural resources, Canadian energy providers nonetheless face a headwind of challenges from market access, to infrastructure, politics, environment and capital constraints. But even in today's bearish market, Canadian companies are adapting—even thriving—through a combination of astute portfolio management, shrewd divestments and timely acquisitions.

This report was prepared by Joseph Hincks, Chloe Dusser, Josie Perez, Angela Harmantas, Ramona Tarta, Katie Bromley and Sholto Thompson of Global Business Reports. For more information contact info@gbreports.com.

Taken at face value, Canada is a fortunate country in terms of its natural wealth. Even as the world's third-largest natural gas producer and sixth-largest oil producer, the country's annual production does not begin to scratch the surface of available resources.

The Canadian Association of Petroleum Producers (CAPP) estimates that Canada's total oil production will double by 2030, rising from 3.2 million barrels of oil per day to 6.7 million, mostly due to oilsands production.

Yet this growth is jeopardized by the United States' domestic energy boom. According to the International Energy Agency's World Energy Outlook, released in November 2013, the US is expected to become the world's largest oil producer by 2015–nearly five years earlier than previous predictions. Currently, Canada exports 98% of its oil and gas south of the border.

Lacking a real export scenario to regions with growing demand, Canada's economy is at risk and its oil and gas industry must adjust if the country is to enjoy the fruits of its natural wealth for years to come.

TSX and TSX-V listed companies

Combining 385 oil and gas issuers, the Toronto Stock Exchange (TSX) and TSX Venture Exchange (TSX-V) are home to more energy companies than any other exchange in the world. With more than 35% of issuers holding properties outside of Canada, issuers are as diverse by geographical focus as by market cap.

Although there are some exceptions, the TSX mostly caters for larger companies; the threshold for oil producers is usually between 20,000 to 30,000 barrels of oil equivalent (BOE) per day of production, providing access to a vast range of institutional investors and mutual funds. The TSX-V, meanwhile, helps micro-caps and small juniors to generate equity capital.

“This two-tiered system has worked well for Canada's junior oil and gas producers, and the venture exchange has been a great first step for companies that want to tap public equity markets,” said Gary Leach, president of the Explorers and Producers Association of Canada (EPAC), whose members are split roughly in half between the two exchanges.

Listing on Tier 2 of the TSX-V, the exchange's bottom rung, requires a company to have adequate working capital and financial resources to carry out its stated work program for 12 months and just C$100,000 in unallocated funds. The relatively low barriers to entry have enabled Canadian companies to go public at a much smaller size and earlier stage than they do in the US or Europe.

In part as a result, TMX Group, the exchanges' parent company, has led globally in new listings for at least the last four years. But it is not just the relative ease of making an IPO that issuers like. TSX encourages all prospective issuers to hold a pre-listing meeting with its listings managers to prepare them for any issues that might arise.

“The venture is very business-oriented and is responsive to the needs of the oil and gas industry,” said Wade Becker, president and chief executive of Pinecrest Energy, which recently moved up to Tier 1 of the TSX-V. “It provides a loose enough structure to deal with the intricacies of energy extraction.”

Stress in the system

Canada's fiscal stability and the efficacy of the TSX and TSX-V have contributed to a world-leading culture of junior exploration. The Western Canadian Sedimentary Basin, occupying more than 1.4 million square kilometers and ranging across the provinces of Alberta, southwestern Manitoba, southern Saskatchewan and northeastern British Columbia, became a globally exemplary model of resource extraction. The model was simple: in most cases a junior would acquire a property and conduct early-phase exploration, raise capital to finance an exploratory drilling program, and then if successful, partner with a larger company, or sell the property off.

However, a variety of factors have disrupted the efficiency of this process. Chief amongst these is the decline of income trusts, thanks to the federal government's 2008 decision to lift the tax advantages that the trusts enjoyed,effectively ending the most profitable exit strategy for junior companies.

The removal of the trusts coincided with ongoing shifts in the upstream industry,including the growth of unconventional resource plays that are more technology-driven and capital intensive. As of July 2013, available capital had decreased by two-thirds compared to the same period the previous year.

This dearth of financing options has placed huge pressure on juniors. “When you are a young company, it is important not to come out of the gate and miss. If you trip out of the gate, there is no way in the capital markets of today's world that you get a second chance,” commented Eric Boehnke, executive vice chairman (Vancouver) of TSX-listed and Vancouver-based Terrace Energy, which is focused outside of Canada on the South Texas cretaceous plays.

According to Bruce Edgelow, vice president, energy group at ATB Financial, an Alberta-focused bank, “Our findings indicate that common equity financing is at the lowest point in five years, significantly lower than during the 2008 financial crisis. We have seen a significant retraction from equity providers that have traditionally raised money to be put into the patch this year.”

Within the Canadian marketplace, there are 226 TSX-listed energy companies. Of these, fewer than 10% have been able to raise capital, said Edgelow. “Those that have are those that have been deemed to be 'A' teams, meaning that with respect to management and board they are viewed as top tier. These companies are also able to aggregate for size, product diversity or a geography that can generate returns,” he said.

A slump in equity markets has meant that capital is far harder to come by than it was two years ago, and the market valuations of companies can be difficult to comprehend. “The markets are supposed to be optimally efficient and always right. Perhaps that will become true again, but a lot of unusual things are happening today,” said Garnet Amundson, president and CEO, Essential Energy Services. “Big pension funds that typically buy shares in companies like ours are trying to protect their shareholders' money as opposed to enthusiastically looking for growth opportunities.”

This downturn is not affecting all companies equally. Terrace Energy has seen its stock price grow from $0.1 a share in January 2011 to $2.1 a share today, success that is predominantly based on shrewd moves to acquire acreage close to the Eagle Ford geological formation in Texas, USA. “Our business model has been to find frontier areas so we can acquire acreage cheaply. We were able to get into our Olmos project for less than $300 an acre, in an area of Eagle Ford where property costs $10,000 to $15,000 an acre,” said Dave Gibbs, president and CEO (Houston)of Terrace Energy.

Yet it also helps that Terrace Energy has looked outside of its home country. While the exodus of capital from equity markets is a global phenomenon, factors endemic to the Canadian industry have made access to capital for juniors particularly challenging. The transition to an unconventional sedimentary basin model has entailed significant changes in project deliverability in Canada. “The cycle times, from money in to money out, have extended significantly. Multistage fraced horizontal wells are highly capital intensive and, while they are very attractive economically, the rate of return profile is longer,” says Shane Fildes, executive managing director for capital markets at the Bank of Montreal (BMO).

Faced with a lack of exit opportunities, some Canadian companies are considering turning their backs on the public markets and exploring private capital to finance their activities. Laricina Energy is a particular success story, having raised over $1.3 billion through private equity to fund its Saleski and Germain projects in Canada's oil sands. “Private equity is becoming more common as an option for good management teams,” said David Vankka, managing director, investment banking at Canaccord Genuity.

Not every investor believes that private equity is the miracle that cash-strapped oil and gas companies are looking for. “The problem with private equity here is that the funds go out to raise money, become increasingly successful, and then face more challenging investment criteria,” said David McGorman, CEO of Jennings Capital.

“Many projects do not need C$100 million to get started; they want C$25 million toC$40 million. Trying to find that amount is very difficult. The conventional hedge fund is not interested, and private-equity firms think this amount is too small for their port folios. Currently the private-equity market raises more money than it knows how to deploy and this goes to companies that have more than they need already.”

Another option for high-performing, producing companies is to start paying a dividend to investors. Whitecap Resources recently established a $0.05 dividend. According to Grant Fagerheim, Whitecap's CEO: “We had to look at it in terms of what we believed our assets could deliver, and how effective we could be with our capital. Now we are setting aside 34% of our cash flow to pay dividends to our shareholders, and the rest is used to fund our growth strategy.”

A dividend model may be attractive to investors, but can consume a company's existing cash flow: the balance between spending money to stimulate investment and saving the investment received is a fine one. Nevertheless, Paul Colborne, CEO of Surge Energy, a light-oil producer in Alberta, believes it is a low-risk way to play their basin. “Surge will grow about 3% to 5% per year and pay a 7% dividend to our shareholders, giving us a return of 11% per year. This model allows us to return a monthly payment to our shareholders who can benefit from strong oil prices,” he said.

Differentials

According to CAPP's June 2013 forecast, Canadian crude-oil production will rise from 3.2 million barrels per day in 2012 to 6.7 million barrels per day in 2030. Oilsands production will account for the vast majority of crude growth, rising from 1.8 million barrels per day in 2012 to 5.2 million in 2030.

But a dearth of transportation options to the coast means that, beyond its small domestic market, Canada is stuck with just one recipient for its oil; the US.

“Having only one customer has made our country vulnerable; we have to find a way to tap into global markets,” said EPAC's Leach.

The widely dispersed revolution in horizontal oil completions and multi-stage fracturing that made exploitation of Canada's oilsands possible has also enabled the US to rapidly increase its production of natural gas and crude oil, light crude, and unconventional heavy oil resources. Limited access to pipelines, combined with the additional upgrading and refining requirements of bitumen, disadvantages Canadian supply. The price difference between Alberta's bitumen—or Western Canadian Select—and West Texas Intermediate peaked at $42 per barrel in 2012, creating a phenomenon known locally as the “bitumen bubble.”.The differential will strip some $27 billion from the Canadian economy in 2013 according to Alberta's finance minister, Doug Horner.

Although the bitumen bubble has shrunk somewhat this year, continued uncertainty around market access has led some to question investing in the oilsands.

“A lot of US funds abandoned Canada for a period of time when price differentials on crude remained high and they had better economic access in their own backyard,” said Canaccord's Vankka. “There is reluctance amongst US investors to come into Canada as crude is trading at such a discount to global benchmarks.

“The valuation differences are going to drive people as time goes on, and some of the transactions we have seen may help, but only if we see deals bigger than 4,000 BOE per day. Global investors need to see the exit strategy in these assets, but without the catalyst to these takeaway problems, investors need to see a real valuation difference.”

Energy infrastructure, overland issues, environmental concerns and First Nations interests have all contributed to a very complex analysis in terms of the likely profitability of the Western Canadian sedimentary basin, said Mark Horsfall, vice chair investment banking for the Canadian Bank of Imperial Commerce (CIBC) “If we are not able to solve some of these issues and create transportation outlets, it is likely that we will be subjected to wider location differentials in the future.”

Alberta's landlocked oil

The European Union's 2011 assessment that oilsands extraction emitted 23% greater greenhouse gases than that of conventional oil extraction put Canada's industry under increased scrutiny. With deliverability issues constraining investment in the oil-sands and putting a cap on profitability, companies are looking to transport bitumen via pipelines in almost every direction possible. This has ensured that environmental concerns have remained in the spotlight.

Enbridge's proposed Northern Gateway pipeline has elicited domestic backlash. The constituency of British Columbia is currently undergoing a provincial election that is set to bring the pro-environmental National Democratic Party (NDP) to power, which, at minimum, may stall the project. In the international realm, the administration of Barrack Obama delayed a decision on the Keystone XL pipeline in November 2011 under environmental pressure.

Given the controversy surrounding the oilsands, innovation is not the first thing that comes to mind. Rather, many think about large producers or new and emerging transportation possibilities, from the Keystone XL pipeline to the ever-growing practice of transportation by rail. Recent innovations in the oilsands seem to have flown under the radar. This should not be the case: oil and gas players have both collaboratively and individually set out to reduce the environmental impact of their operations, in turn reducing costs.

Producers such as Baytex Energy, Southern Pacific Resources and Connacher Oil and Gas are already moving product by rail and, in some cases, barge to circumvent infrastructure bottlenecks.

Christopher Bloomer, CEO of Connacher, explains the logistics involved in moving bitumen by rail: “Early on, you basically trucked oil to a pipeline terminal and put it in a pipeline, or you trucked it to the local market. Now you can rail oil to specific markets that may view the value of your product differently, but this is a very dynamic situation born out of necessity. Pipelines will get built, but Connacher will always be a trucker/railer of bitumen, whether inter-Alberta or ex-Alberta; that will be our approach until we get up to substantial volumes.”

However, the explosion of an oil-carrying train at Lac-Mégantic in Quebec in June, Canada's worst rail disaster in almost 150 years, has caused many to question the increase in rail transportation in North America. New and safer methods of transporting crude are possible, explained Ron Daye, president and chief executive of Rangeland Engineering.

“The large rail transloading facilities are not new, but with so many coming on, the technology, whether it is loading arms or vapor displacement systems and controls, is changing. Typically, a rail facility 10 years ago would handle 10 cars per day. Today, we are developing systems that are handling 100 to 300 cars per day.

Piping and pumping systems are large, and the processes to accommodate this size must become more innovative. “We have been working with specialized vendors that supply equipment to this industry and we are working to make the systems more efficient through innovation in the design,” Daye said.

While rail transport is stepping up as a result of necessity, the safest option to transport crude, according to the vast majority interviewed, is still pipelines, making the delays surrounding Keystone, Northern Gateway and the East-West pipeline routes even more frustrating. Despite its potential to relieve some of these bottlenecks and its expected impact on Canadian coffers, the Northern Gateway project has numerous opponents, ranging from environmental organizations to First Nations communities along the pipeline's proposed route.

At the end of May, the British Columbia government formally rejected Enbridge's Northern Gateway proposal on the grounds that it did not address the province's environmental concerns. Of particular concern was spill response. “Northern Gateway has said that they would provide effective spill response in all cases. However, they have presented little evidence as to how they will respond,” British Columbia minister of environment Terry Lake said.

Such concerns will seem especially acute in light of the recent small crude-oil leak on the Trans Mountain Pipeline near Merritt, British Columbia. “The Alberta energy regulator and the public have little tolerance for pipeline leaks, as they should,” said Bill Forrest, manager, Canadian operations of FlexSteel Pipelines. “If companies have a choice between building a steel pipeline that may or may not leak, versus composite pipelines that do not leak, you can see the trend heading toward even higher standards. Producers have nothing to gain and everything to lose from pipeline leaks.”

Ultimately, because the proposed pipeline crosses provincial borders, it will be Canada's federal government that decides whether Northern Gateway progresses. “We have seen the federal government make some very strong statements towards the ENGO (environmental non-government organization) groups that clearly indicate that the federal government is a champion of the line,” Allan Ross, Alberta's representative in Ottawa at the Ministry of International and Intergovernmental Relations, told GBR.

But would the government take the dramatic step of using its constitutional power to legislate the pipeline into existence? “My sense is that the federal government would not, particularly if an eastward line and Keystone are coming into place,” said Ross.

Battening down the hatches

As the constricted market causes companies to become leaner and more efficient, and with industry-wide emphasis on growth through the drill bit and the reallocation of stranded assets, analysts predict that the Canadian companies able to ride out the current conditions will be in a much stronger position when the markets recover.

But even in today's bearish market, some Canadian companies have thrived through a combination of astute portfolio management, shrewd divestments and timely acquisitions. Arguably more than ever before, a strong, experienced management team is vital for inspiring investor confidence.

Manitok Energy, which was one of the TSX-V's top 10 performing oil and gas companies in 2012, focuses on conventional oil and gas reservoirs in the Canadian foothills along with heavy crude oil in east-central Alberta. Following successful capital raising programs in 2010 and 2011, Manitok Energy again went to market in late 2012 and raised around $18 million.

“Drilling in the foothills was 30 years behind the Deep Basin and the Peace River Arch, so there was an opportunity for big results. The problem was that there had been at least 10 juniors in the last 20 years trying to do the same thing, and all of them had failed, so there was a lot of skepticism in Calgary,” Manitok's president and CEO Massimo Geremia, said.

One of Manitok's key differentiators was the experience of the management team and the match between the asset and the skill set of the technical team. Led by chief operations officer Tim de Freitas, Manitok employed a series of experts that had previously worked in the foothills with Talisman Energy.

“All of the other companies had been started by deep basin guys, or junior guys who had never drilled in the foothills and had to learn the pitfalls the hard way. Tim and the team from Talisman had already spent C$3 billion or C$4 billion dollars and more than 10 years in the area getting to grips with the pitfalls,” said Geremia. “If you look at the junior companies that have prospered in Calgary over the last 30 years, a lot of them start with guys leaving the major firms and knowing the assets very well.”

For companies with strong balance sheets, or those prepared to take on debt, asset divestiture presents a rare opportunity to pick up underdeveloped assets. Sub-C$15 million market capitalization Edge Resources was able to raise just over $6 million in early 2013. According to CEO Brad Nichol, a close and open relationship with investors was integral to achieving this.

“Debt is by far the least expensive and most readily available form of capital available today,” said Nichol. “I think our greatest asset outside of the physical properties is that we have some great partnerships with our investors. Many juniors are struggling and lots of assets are underdeveloped, so there are many acquisition opportunities that we are working with our partners to take advantage of,” said Nichol.

Other companies have had to refocus and reposition themselves to adjust to the challenging equity markets by selling assets. Connacher Oil and Gas, a junior oilsands player in Alberta, overhauled its management team and sold their downstream assets to focus on production at the Great Divide oilsands project in Alberta.

Prior to the reorganization, the concept of Connacher was in-situ oilsands hedged against gas with conventional assets, and then the downstream aspect. The market turned and performance was trailing, and the company had a balance sheet issue, according to Christopher Bloomer, Connacher's recently appointed CEO. The board and the previous management were able to sell the refinery to put capital on the balance sheet and start to re-focus the company.

“Connacher's business was good—with reservoir geology in the top 10% of our peer-group—but the balance sheet needed to be right-sized,” Bloomer said. “The priority at the moment is positioning Connacher to show that it can invest capital and grow, to warrant people to say that the business deserves more capital because it has value.”

Eastern trade winds

2012 was a bumper year for Asian investment in Canada, with blockbuster transactions such as the CNOOC takeover of Nexen, and Petronas' buyout of Progress Energy capturing headlines. While the C$6-billion Petronas/ Progress deal passed government scrutiny without incident, the $15.1-billion merger of CNOOC and Nexen prompted Ottawa to enact a series of changes to the Investment Canada Act that specifically targeted foreign ownership of Canadian oilsands assets. In December 2012, the federal government moved to block foreign takeovers in the oilsands except on an “exceptional basis” in circumstances that constituted a “net benefit” to Canadians. Neither term was clearly defined, nor was an example of exceptionality or benefit provided.

Unsurprisingly, foreign investors are left wondering how they might be able to play in Canada's oilsands, and the viability of making investment overtures that could potentially be killed by the government. Mark Horsfall of CIBC said, “Our buy-side clients in Asia and elsewhere, which are state-owned or state-affiliated, are trying to discern what these changes mean for them. This has not lessened their interest in doing business in Canada, although we expect opportunities will be pursued more cautiously.”

“The government's message after the CNOOC-Nexen deal is clear: state-owned enterprises should not get involved in Canadian oilsands except in 'exceptional circumstances,'” said Michael Laffin, partner and chair, Asia region at Blakes Cassels & Graydon LLP. “What is not clear is the government's definition of a state-owned enterprise–does it extend to companies that are influenced by their government? In that case, why do we allow companies like Statoil to invest heavily in Canada?” Chinese companies have independent directors to make sure that they abide by Canadian law, and undertakings to give to the federal government in the form of a net surplus test, he said. “The restrictions placed on oilsands investment should not affect other resource plays in Canada in terms of access to foreign investment. In terms of oilsands, it may take some time, but the government will see that foreign investment, including that of China, is needed to develop the resource. The costs are too significant to develop alone.”

Separately, some Canadian companies have navigated a route through the capital-constrained Canadian market by partnering with cash-rich Asian players with a keen interest in Canadian assets, and particularly the oilsands. Founded in 2006, Athabasca Oil Corp. is focused on the sustainable development of oilsands in the Athabasca region in northeastern Alberta and light-oil resources in northwestern Alberta. After having proved up its oilsands reserve base to 10.3 billion barrels of contingent resources (best estimate) in early 2010, Athabasca sold 60% of its working interest at its Dover and MacKay oilsands projects to PetroChina for gross proceeds of C$1.9 billion.

Following the sale, Athabasca partnered with PetroChina to develop its newly acquired Hanging Stone property. “PetroChina had been looking at oilsands from about 20 years ago and actually helped to fund the original SAGD (steam-assisted gravity drainage) pilot in Alberta. In 2009, when Athabasca Oil started looking for a partner, they were ready,” said Sveinung Svarte, Athabasca Oil's chief executive. “They decided that this was a good opportunity now that the technology is mature, that Athabasca had great projects and PetroChina had faith in our ability to deliver.”

The deal with PetroChina was concluded after about eight months of negotiations and at the time Athabasca had just 14 employees, while PetroChina had some 1.6 million. According to Svarte, partnering with PetroChina has been a good experience.

“Athabasca's model for financing has been focused on joint ventures from the early days. We built the company for that purpose and we hired people with international experience. It is important that you have the cultural understanding and the patience to work with people from different origins. We already had an internal culture of welcoming people like PetroChina.”

The prospect of Asian investment in Canada led TMX Group to open a representative office in Beijing in 2011 and the corporation has a specialist focused on Asian markets. However, because of the structural impediments, it is doubtful that there will be a flood of Asian retail or institutional investment into Canada.

This issue can be at least partially circumvented by companies launching IPOs in Asian markets: the most obvious choice being in Hong Kong. However, although dual listing is relatively common for oil and gas juniors and many of the larger TSXlisted players also issue on the New York Stock Exchange, listing in Asia remains fairly unusual, with only a handful of Canadian companies currently listed in Hong Kong. Yet as these markets show increasing maturity, this option should see increased uptake.

Asian capital is not exclusively reserved for oilsands plays. Bellatrix Exploration, which holds a large Duvernay shale inventory, is focused on drilling in the Cardium and is also developing a Notikewin liquids-rich play. It formed a joint venture with a South Korean company to accelerate the development of some of its inventory.

“The question comes down to, how we can derive value to hopefully translate to an increase in our stock price? That is why we believed that the joint venture was the appropriate path to accelerate a small amount of our inventory and increase our cash flow,” Brent Eshlesman, executive vice president of Bellatrix said. “Our philosophy has been to keep a clean balance sheet, because if a company has too much debt and the industry turns for the worst, it is stuck selling core assets at a very low price.”

The next frontier: Canada takes aim at LNG projects

Nestled in the middle of the Rocky Mountains, Kitimat is a sleepy town in northeastern British Columbia that is poised to become the next boom town in Canada, thanks to proposed development of liquefied natural gas (LNG) plants and terminals by a variety of multinational oil and gas players. Currently, three consortiums—Shell/PetroChina, Apache/ Chevron and Petronas/Progress Energy—have invested a combined C$35 billion into early-stage projects. If these proposals are to go through, Kitimat and the excitement surrounding LNG in Canada may be the saving grace for Canadian natural gas.

The Montney, one of the largest natural-gas producing basins in Canada, sits right on the British Columbia-Alberta border. It is one of the few plays where Canadian gas juniors can currently operate and hope to gain any sort of investor recognition. As it stands, drilling activity in the Montney dropped off last year due to low gas prices. The key is finding and producing liquids-rich gas.

“Further up from the Montney there are more liquid-rich reservoirs that are gaining increasing appeal over dry gas,” said Keith Braaten, CEO of GLJ Petroleum Consultants. “Although there are fewer resources there, the Montney presents higher prices for developing projects. At C$5- to C$7 million per well drilled, the gas price would need to be very competitive. Companies are no longer drilling for production, but to identify resources for their LNG plants.”

Many Canadian service companies have moved their attention to LNG. “Right now, the big play in Canada is the LNG opportunity,” said Brent Conway, president of Trinidad Drilling. “There are significant hurdles in terms of getting the approvals to build pipelines, and decide who is going to build them, but it will happen.”

The strategy will mimic the past, he said. ”The E&Ps will figure out how they are actually going to drill and complete those wells, and then there will be a much bigger ramp up. It makes sense to get this trapped gas off the continent and into a market where it is going to get a decent return, but it is going to take some time.”

Even so, the LNG opportunity could induce a profound shift for Canadian service providers and an important shift for US service providers, according to Kevin Neveu, CEO of TSX-listed drilling company Precision Drilling.

“Typically, North American natural gas has been a high-demand option play. What is different about LNG is that these are mega projects. Moving LNG is deeply capital intensive; it requires large pools of capital with long horizons. If you are building an LNG export facility that is going to be exporting 145 billion cubic feet (Bcf) of LNG, you need 20 years of drilling to support that.”

This creates a whole new paradigm of business opportunity, Presicion's Neveu believes. “We think that, in Canada, the LNG facilities that get built will include export facilities, pipelines and complete field developments tied to that export facility. It is likely that the rigs that go into those fields will be designed to operate for 20 years in one field. They will drill 365 days per year on pads. It will be a business model that Canada—which tends to be highly seasonal and commodity price dependent—does not often see.”

There are still reasons to be cautious about the proposed level of development in Canada's LNG space. Chief among these is the length of time these large-scale projects will take to get off the ground.

“Projects will be spread out over a period of time, and I would not be surprised if some are consolidated over time,” said David Collyer, president of CAPP. “A wide range of proposals is not unusual for the early stages of LNG development, but competitiveness demands fewer, larger facilities. CAPP's industry projections assume that not every project will go ahead at the same scale and in the time-frame it intends.”

International competition is also a factor: both the United States and Australia have large LNG projects currently at an advanced stage. “Canada's LNG projects are greenfield projects, and there is competition from more brownfield projects in the US,” said Janice Buckingham, partner at law firm Osler Hoskin & Harcourt LLP. “We are expecting some consolidation in the LNG space to occur over the next 12 to 18 months, on a project basis.”

“I believe Canada will do well, but that it will be a tougher climb with lower margins than envisioned by some,” cautioned CAPP's Collyer. “People are talking about 2017 for the first projects, but I think this is ambitious.”

“The most important thing is that we have determined that these legacy gas and oil fields that we thought were played out actually have a very good economic life and lots of resources in place,” said Precision Drilling's Neveu.

“The politicians and the environmentalists have to understand that you do not go from a carbon-based economy to a zero-carbon economy in one step; you have to wean yourself off carbon.” And while natural gas is a little less efficient than diesel and gasoline, it is a much lower-carbon option, he said. “From burning brush, to burning wood, to burning low-quality coal, to high-quality coal, to oil, and now gas, mankind has continued to move down the carbon chain. I think that natural gas, and moderate-cost shale gas, is a good long-term bridge as we find better solutions for our long-term energy supply.”

Midstream grows in Canada

With LNG development on the horizon, one of the more interesting sectors for Canadian companies is in midstream opportunities such as oil and gas processing, terminaling and transport. Over 60% of Canadian producers currently own their own midstream assets, but with major upstream players such as Encana Corp. recently divesting its midstream assets, this is poised to change.

Don Althoff, chief executive of Veresen Energy, a TSX-listed midstream company, extolled the value of the midstream player within a vertically integrated supply chain. “It makes sense in the current economy for producers not to own their own midstream assets. The only reason to want to build and own pipelines is if they somehow gave you a competitive advantage.”

Enough infrastructure exists already that producers do not need to own it themselves, he said. “It is partly a legacy issue that is tied to the evolution of the junior community in Canada's oil and gas industry. Previously, it made sense for juniors to own midstream assets because it gave them some strategic advantage when they sold their projects to majors. The midstream market has evolved to the point where there are so many established players who can transport and treat product that it no longer makes strategic sense for a producer to own these assets themselves.”

For a relatively small market as compared to the United States, where only about 20% of producers own midstream assets, there are a number of billion-dollar midstream companies in the Canadian space: ATCO, Keyera and Pembina are just a few players who are solely focused on linking producers with their customers. The opportunities are such, however, that newer midstream companies like Kanata Energy are breaking into the market.

Kevin Cumming, CEO of Kanata Energy, believes that Canadian companies are beginning to take notice of the value of midstream players.

“There is a greater movement toward the midstream model in Canada. A number of companies have assets in the US, where the ownership of midstream assets by producers is closer to 20%. Other companies would rather spend capital on the drill bit rather than infrastructure.

Midstream returns are in the mid-teens, whereas the upstream industry targets more than 30% returns. “For every dollar spent on the upstream side, about 20% to30% has to be spent on the midstream side, so why spend that money when it can be re-injected into a higher-return business? A properly run midstream company can add a lot of value to an upstream company that they may not have in-house,” he said.

Despite the enthusiasm, it might yet be too early to invest heavily in midstream opportunities when many of the larger-scale LNG and oilsands projects are yet to be fully committed.

“Midstream companies are ready to take advantage of the growth opportunities in the sector but not sure how to capitalize on this growth,” said Bud Strandquest, senior vice president, Canada, at MTG, a US-based consulting company. “There are many opportunities coming from the expansion of pipelines, transport options and the building of refineries, but none of these plays are at a level of certainty for companies to deploy capital.”

Using LNG as an example, some 10 projects are being planned at the moment, but it is unlikely 10 different large-scale projects will come to fruition. “There needs to be more assurance that the expected market will in fact be in place—coming in the form of regulatory and permitting approvals—before anything happens. Midstream development will follow capital deployment in these areas.”

The service sector

Canada's oilfield services sector is enjoying more stability than its upstream clients, with committed capital expenditure already in place despite the tighter equity markets of late. The sector, however, is certainly not immune to the challenges faced by the wider industry. Service players too must adapt to the changing faces of clients and projects in the Western Canadian Sedimentary Basin.

“There has been a demographic shift in our client base,” said Wade McGowan, president and CEO of Ironhand Drilling. “Historically, we have not chased the larger multinationals or national oil companies, but we recognize that as we add rigs, those doors will open. Large upstream companies work with large service companies due to elasticity of supply. Juniors and intermediates typically only run a few rigs year-round.

“From a corporate perspective, we have seen the emergence of multinationals in the Duvernay and Montney, and we have to manage that risk. The basin is transforming into a playground of multinational super-majors and national oil companies who do not depend on the public markets for cash flow. Investors seem to think that there is work coming for oilfield service companies, but the proof is yet to be seen.”

The nature and number of foreign transactions in Canada's oil and gas space forces service companies to deal with new entrants. Randy Karren, group managing director, Improve, at WorleyParsons in Canada, termed it a “new game” in the Canadian marketplace. “We are seeing a lot of foreign investment into the oilsands, and we must figure out how to work with new customers who are used to working differently,” he said.

A separate issue affecting engineering companies is the changing nature of client expectations given the tighter equity markets and increased competition from international firms. “Rising cost pressures have forced many firms to contract overseas and, while this may allow for a lower per-hour billing rate, the amount of time required to get a project done is much longer,” said Kurt Horner, president of Calgary-based Fortress Engineering.

According to John Pearson, global managing director with energy engineering firm Hatch, the biggest change is that clients now perceive the engineering process as a cost rather than an investment. In an era of extreme cost control, producers may feel obligated to go with the cheapest engineering option.

“Engineering is an investment that needs to be phased and implemented properly to generate returns,” Pearson said. “If it is viewed as a cost, the tangential effects of improper implementation can cost way more than any initial savings. We pride ourselves on being the lowest cost engineering provider, not through savings up front but by the time it takes for projects to get into production. Unfortunately, there is a race to the bottom on finding ways to take money out of the intellectual property that is delivered, which is flawed logic.”

WorleyParsons' Karren notes that few people are doing detailed design work. He explained, “Most of our work is for customers who have a reservoir capability, and have a plan of how they would like to extract oil. WorleyParsons helps with some of the pilot plants, but the client owns the process itself.”

While the clients and expectations within the large-scale oilsands projects may be changing, some companies see more opportunity in smaller projects overlooked by the WorleyParsons and Hatches of the world. Rangeland Engineering, a mid-sized Calgary-based engineering firm, is targeting projects on the fray of production, such as rail transport. “The majors are looking for $1-billion projects, but that is not our game; we work on projects that are $300 million and less,” explained Ron Daye, president and CEO of Rangeland. “When these larger players are looking at these larger projects, they are not paying attention to the off-sites or smaller projects, whereas we do.”

The amount of work to come in the service sector means that it represents an attractive sector for merger and acquisition opportunities. According to a recent Deloitte report examining oil and gas M&A activity, the global oilfield services segment was very active during the first half of 2013, with the number of transactions rising to 51 from 39 as compared to the previous year, at a total value of C$11.1 billion.

Not surprisingly, Calgary-based advisory firm Stormont Energy Partners is eager to be a part of this heightened activity.

“Many of the companies that we see buying in Canada want to have exposure to infrastructure, in particular to oilsands infrastructure, including construction capabilities, fabrication or instrumentation and electric-service companies,” explained Dave Munro, managing director of Stormont, a financial services firm focused on oilfield services transactions.

“The development of the oilsands is a human- and capital-intensive business. What we have seen is that the scale of that operation and the ability to modularize, meaning building off-site and assembling the pieces at a later point, is becoming more attractive. The process was much more complicated before and this scared people out of the sector because it involved huge capital costs and risk from the service perspective. Today, we can put our arms around the difficulties; we can break up the process, which allows for the creation of many service companies to provide service in an area.”

Green technologies

Accounting for 98% of Canada's oil reserves, predominantly contained in the oilsands, the province of Alberta is leading the charge to increase production in an environmentally sustainable manner. In addition to already extant monitoring systems, in February 2012, the Alberta government announced the Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring. The plan seeks to gain an increased understanding of the long-term effects of developing the oil-sands and ultimately detail how the Canadian and Albertan governments will implement a world-class monitoring program to ensure that the oil sands are developed in an environmentally responsible fashion.

One of the areas in which Canadian innovation is being applied is oilsands tailings management. “One of challenges of oil-sand tailings ponds is the length of time they need to be reclaimed; the more water content you have, the longer the process takes,” explained Dave Kerr of global environmental sciences firm Golder Associates.

Canadian companies are pioneering novel approaches to separating oil from sand, and dewatering mine waste. Hatch is working on a method that seeks to separate oil from sand without using water.

“N-Solv is a solvent-based in-situ technology that uses a pure solvent as the method of liberating oil from sand. We have proven the technology in a lab and are now applying it at a pilot project on one of Suncor's sites. If it works, it uses 90% less energy and actually produces water by liberating it from the ground. You are left with a recyclable solvent that eliminates the use of natural gas to burn steam. It leaves you with truly 'green' oil,” said John Pearson, Hatch's global managing director, energy.

Golder Associates uses paste technology in a number of oilsands mines in Alberta. “The paste process is essentially the process of de-watering material waste,” explained Sue Longo, associate, paste engineering and design, Golder Associates. Historically, waste was mixed with water and deposited into tailings ponds, but paste separates solids from water in the waste management stage rather than during the extraction phase.

“The technology allows for drier deposits that can be managed with a smaller footprint with a positive topography. For example, run-off is manageable, and there is nowhere for ducks to land because there is no water. Surface disposal has taken a little more time to become mainstream, especially in the oilsands; nobody wants to be the first to try something new and unproven. You can always make the process work depending on how much money you want to spend.”

However, the use of new technologies and approaches can only go so far in reducing the impact that oil and gas extraction has upon the environment. Canadian companies are arguably under greater environmental scrutiny given the international perception of Canada's oilsands as “dirty oil.” It is worrying, then, that companies like WorleyParsons are seeing a decrease in demand for environmental services, viewed as discretionary services in an era of tight cost control.

Business performance and environmental management are inextricably linked, according to Golder Associates' Kerr. “For a long time, the environmental component of the approval process was seen as a necessary evil, but that has changed rapidly over last 10 to 15 years.

“Today, there is a much stronger emphasis on environmental design as well as engineering design, with projects first looking at the best way to develop a resource technically and then linking that to environmental and social inputs, the constraints and opportunities. Corporate social responsibility requires the demonstration of a commitment to three segments of sustainability—environmental, social and economic—and these are all playing a much stronger role even in the earlier stages of concept development,” he said.

Canada, the petro-state: (How Alberta's regulator was eaten by its super regulator)

In December 2012, Alberta passed “Bill 2,” the Responsible Energy Development Act, which authorized the new Alberta energy regulator to assume the regulatory functions of the Energy Resources Conservation Board (ERCB) and Alberta Environment and Sustainable Resource Development with respect to oil, gas, oilsands and coal development.

The act, which passed on the back of recommendations made by the Regulatory Enhancement Task Force made two years before, effectively created a ”super regulator,” combining two previously separate regulatory bodies. According to its implementers, the change will reduce regulatory duplicity and make both the approvals process simpler.

“If you are doing a SAGD project in the oilsands, it could require as many as 200 separate licenses.We are turning that into a one-window approach and, if we can take a few months off the process, it provides huge value to the applicants,” Alberta's minister for energy Ken Hughes said.

Neil McCrank, the former chair of Alberta Energy and Utilities Board, said that the new system would benefit not just industry, which would have one approval to get instead of two or three, but also the public. “A farmer faced with the prospect of a well being drilled on his land currently has Alberta Environment to deal with, he has the Surface Rights Board, and the ERCB; now, he will have one place to go.”

According to McCrank, the latest changes are natural developments for a regulatory system that has been world renowned since its inception some 75 years ago. The enduring strength of the regulatory system has been a key factor in the development of a cutting edge, extractive industry in the province.

Unlike most oil and gas jurisdictions, including mature North American jurisdictions such as Texas and Oklahoma, where companies drill a well and then keep the information they discern to themselves, Albertan regulations dictate that following a one-year, tight-hole confidential status, everything becomes available to the public. In addition to promoting a culture of accountability, this means that prospectors can go to the core research center in Alberta and the logs are all publicly available.

Relative to other jurisdictions, the Alberta approvals process is considered timely and thorough. Athabasca Oil CEO Svarte emphasized that Alberta is an oasis when it comes to approvals. “It takes time, but at least it is predictable. Alberta is not like British Columbia; here the government gets it through and, if necessary, they call a public hearing. It is frustrating to see investors in places like New York who say, you have upcoming discussions with stakeholders—you'll never get it built. The regulatory system here and the regulators are very sophisticated, high-quality people. The problem is that the industry has hired from them, so the regulatory body is losing very good people,” he said.

But the key distinguishing feature of the Albertan system has been its history of regulatory independence. “The body that has run the regulatory system in Alberta has always been seen to be at arms length from government and independent in its decision making, which means that you take out the political environment or influences from decision making,” said McCrank.

As chair of Alberta Energy and Utilities Board, McCrank has lectured on the success of Alberta all over the world. “In some Latin America countries, I would explain the system and then get to the point that one of the keys is to have decision-making power independent from the political environment. That was unheard of in most jurisdictions. They were not prepared to accept it because the political people wanted to continue to meddle.”

Although most respondents were in favor of reducing regulatory duplicity in Alberta, some were concerned that one section of Bill 2 had the potential to compromise the regulator's independence from the government. Bill 2's Section 67 provides that when the minister considers it appropriate, the minister may by order give directions to the regulator to provide priorities and guidelines for the regulator to follow in the carrying out of its powers, duties and functions, and to ensure the work of the regulator is consistent with the programs, policies and work of the government in respect of energy resource development, public land management, environmental management and water management.

McCrank said he would be concerned with Section 67 if it were in any way an attempt by the government to interfere with the independent thinking and decision-making power of the board.

“If they use it in an inappropriate way—and I hope they would not—they will cause the board to lose its independence. I hope that it will never come to the point where industry is going behind the scenes to get government to direct the board in some fashion. We cannot have industry and government trying to make these kinds of decisions because they are all short-term. The regulatory body is supposed to make long-term decisions in the public interest, not decisions for every election. Bringing political sensitivity to the table when you are making long-term decisions is problematic,” he said.

Beyond Alberta

The 10-square blocks that form Calgary's central business district are home to one of the highest concentrations of oil and gas companies in the world. The board rooms here look much like board rooms anywhere else; a central table is surrounded by walls hung with geographical maps. However, Calgary-based juniors have a vast geographical footprint, and the locations depicted on these maps are extraordinarily diverse.

Deciding where to invest can involve a variety of tacit considerations, but two ideas are prominent in most calculations: exploration risk, which in addition to geology can also encompass infrastructure, market demand, and operating costs, as well as political risk.

The maps hanging on the walls of CYGAM Energy's 12th Avenue SW offices depict the company's flagship assets in Tunisia, where, according to CYGAM chief executive David Taylor, the popular perception of political risk is way off-base.

“It does not help that pictures of riots and cars burning make great press, but Tunisia has actually been much more fiscally stable than Alberta. Unfortunately, a lot of domestic investors are really quite parochial and will never arrive at an accurate assessment of Alberta,” said Taylor.

Perhaps the political risk profile of a jurisdiction has more to do with its fiscal constancy than the stability of its leadership.

In Egypt, over the past two years of protracted Arab Spring, Calgary-based Sea Dragon Energy has doubled production from 1,000 to 2,000 barrels per day and acquired additional assets. “Sanctity of contracts is central to Egypt, a country with a long heritage in oil and gas, and fiscally Egypt offers a very solid environment,” Seadragon Energy CEO Paul Welch said. “Business carries on. In fact, asset prices have dropped and we have been able to pick up property below market prices, so from our perspective, it has been very positive.”

Misunderstanding of political risk, at least in the terms of how it affects oil and gas plays, is often compounded by investors conflating political risk with security risk.

However, according to Petrominerales CEO Corey Ruttan, who is involved in Colombia, recently investors have evolved their perception of risk. “When the Alberta government introduced sweeping changes to the fiscal regime here, I think Canadians began to understand the difference between political and security risk,” he said.

High operational costs, price differentials and a shortage of frontier exploration opportunities in Canada have been a push factor for some Canadian juniors who have found more opportunities abroad, and the memory of 2009's tax hikes caused some to question the conventional wisdom that the developed world, and Canada specifically, is without political risk.

“Nowadays, western countries have significant political risk, if taxation is considered one of its elements,” said Don Streu, president and CEO of Condor Petroleum, which is developing properties in Kazakhstan.

However, according to McCrank, who formerly headed the Alberta regulatory body ERCB for 10 years, the royalties hike was a good example of something that went wrong but was reversed in due course.

“In any jurisdiction, the regulator can make mistakes, the government can make mistakes, and the industry can make mistakes.But in the system we have, mistakes get rounded out over time, which is sometimes not the case in Tunisia, for example,” he said.

Papua New Guinea: The next destination for gas exploitation

Papua New Guinea's geological prospectivity, combined with its access to large Asian LNG markets, has long captivated the attention of the world's major E&Ps. The country, now on the verge of big monetization events such as ExxonMobil's US$19-billion LNG project and the Inter-Oil Gulf LNG project, is looking an increasingly appealing investment destination.

However, despite improving political stability and the aforementioned proof of major-project deliver-ability, the barriers to entry are high for juniors looking for a piece of the action. “From a first-world perspective, it is exceedingly frustrating how slow things are,” Brad Humbertise, CEO of Eaglewood Energy, said.

Calgary-based Eaglewood, a PNG pure player, is participating in the Stanley Fields project and holds a 12,000-square -kilometer land base over five significant licenses in Papua New Guinea's prospective Forelands.

Project delays are just one aspect of operating in the country that is highly capital intensive. However, having an operating team with significant in-country experience has helped Eaglewood Energy mitigate some of the risk.

“Our strategy has always been to employ an indigenous workforce, and our country manager is a Papua New Guinea national who has spent a long time with the regulators. Furthermore, being a pure play, we are able to monitor the situation very closely,” Humbertise said.

Eaglewood also has been farming down its interests. With a rejuvenated balance sheet, the company planned to drill a Forelands exploration well in fourth-quarter 2013.

While a company in a jurisdiction such as Papua New Guinea can ensure it employs experienced locals and maintains a strong balance sheet with a realistic project focus, the government has to play its part too. “Our message to the regulators is that, if the delays are too long and we just can't operate in this country, junior companies may leave and stop stimulating the activity that results in the government receiving the royalty capital at the end of the cycle,” said Humbertise.

Capital for Calgary's overseas players

More than the Australian Stock Exchange, or the London AIM, which developed a reputation as a punters' market, the TSX and TSX-V are considered credible exchanges for juniors to access global capital. However, as with domestically-focused players, depressed markets make equity capital hard to come by no matter where the project.

For many juniors, the need to appeal to a shrinking pool of investors is a key consideration when building a portfolio of assets. According to CY GAM Energy's Taylor, investors prefer to compartmentalize jurisdictional risk rather than backing companies operating across different regions. “Fund managers, institutional investors and portfolio managers all take the view that companies should either be domestic or international...very few companies have succeeded with a mixed model,” said Taylor.

Operating as a pure play has advantages: the narrowed focus enables investors to select their preferred portfolios and potential partners to more simply acquire companies. Operators also ascend the experience curve more quickly. Terrace Energy, focused on utilizing unconventional techniques in the cretaceous plays of South Texas, had their expertise noticed by Shell, who invited them to be their science team on the Pearsall, a new play with similar characteristics to Eagle Ford formation. “Unconventional drilling makes projects economically viable because they emulate conventional five acre spacing, just down a hole. We are spending four times what a conventional well costs and creating 14 times the return,” said the company's president Dave Gibbs.

Yet for some the ability to concentrate expertise is not worth the costs. “The challenge of just being in one country—and the regulatory wheels grind slowly, and the operations grind slowly—is that it is hard to have enough news flow to keep investors interested,” said Eaglewood Energy's Humbertise. “Although we have been very active in the last year, that does not seem like the case from the outside looking in. The reality is that delays are inevitable in these jurisdictions, so you have to be much more careful with announcements,” he said.

The consolidation of an asset base for the sake of investor simplicity is unlikely to make sense. In some cases, companies have actually diversified from being a pure play to having a split domestic-international asset base.

Prior to making the decision to buy its Canadian assets, Madalena Ventures was an Argentinean land play, with a focus on drilling and delineating large shale plays. However, the Canadian assets provided production well sites: generally a much more stable source of capital. “Overall, the Canadian assets provide sustainability for the company in order to drive our vision in Argentina. This has turned into a longer-term project and we are looking to build up production and 2P (proved and probable) reserves,” said Kevin Shaw, CEO of Madalena Venture.

The majority of Madalena Ventures' short-term production growth will come out of Canada and the company will invest the generated capital into delineating its shale plays in Argentina.

Latin America has traditionally been the starting point for Canadian oil and gas juniors looking for a find, but the next big discoveries might come from previously overlooked destinations. According to Jim Davidson, CEO at First Energy Capital, “The advent of new horizontal, multi-stage fracing technology has opened up many plays in jurisdictions that have previously been overlooked.”

Poland, for example, has a very large shale play. “We are going to see oil and gas activity taking place in regions that we have not seen before, as plays that were previously not profitable become more attractive with the application of new technology.”

Facing the future

The number-one priority for Canada's oil and gas industry is to find a solution to export its abundant supply of crude oil and natural gas.

Crude by rail has emerged as a stopgap measure but may lack the ability to handle the anticipated rampup in production. The demand scenario is changing as well: the International Energy Association expects demand for oil to rise 27% over the next 20 years. Two-thirds of that growth will come from Asia, a market that is currently difficult for Canadian producers to access.

The stinging point for cash-strapped Canadian producers is that there is an available pool of capital ready to invest, but hesitancy to do so. In the USA, companies have never had so much money on their balance sheets and want to put it somewhere. Whether or not this source of capital will make it north of the border clearly depends on Canada's ability to solve its issues and create an economically viable and environmentally sustainable industry deserving of the country's enormous oil and gas potential.